The present invention relates to a process for oil recovery by tenside flooding.
In extracting oil from petroleum deposits, usually only a fraction of the originally existing oil can be recovered by primary extraction methods. In these methods, the oil is brought to the surface by harnessing the natural reservoir pressure. In secondary oil recovery, water is forced into one or several injection wells of the formation and the oil is forced to one or several production wells and thereafter brought to the surface. This so-called water flooding is a relatively inexpensive secondary measure; accordingly, it is utilized frequently. However, in many cases it results in only a minor additional oil extraction from the deposit.
Effective displacement of such oil, which, though more expensive, is urgently required from the viewpoint of the national and international economy in view of the present petroleum scarcity, is accomplished by tertiary measures. These include processes wherein the viscosity of the oil is reduced and/or the viscosity of the flooding water is increased and/or the surface tension between water and oil is decreased.
Most of these processes can be classified as solution flooding or mixture flooding, thermal oil recovery methods, tenside or polymer flooding and/or as a combination of several of the aforementioned processes.
Thermal recovery methods involve injection of steam or hot water, or they take place as an in situ combination. Solution or mixture processes involve injection of a gaseous and/or liquid solvent for the petroleum into the deposit.
Tenside flooding processes, depending on tenside concentration, optionally, on the type of tenside, and on the additives used, are differentiated as tenside-supported water flooding, the usual tenside flooding (low-tension flooding), micellar flooding, or emulsion flooding. These processes are based primarily on a strong reduction of the surface tension between the oil and the flooding water. However, in some instances, especially in the presence of relatively high tenside concentrations, water-in-oil dispersions are produced. These have a markedly increased viscosity as compared with the oil. Tenside flooding processes, then, generally are aimed toward a reduction of the mobility ratio whereby the degree of efficiency of oil displacement is raised.
Genuine polymer flooding is predominantly based on the last-mentioned effect of a more favorable mobility ratio between oil and flooding water.
Heretofore, organic sulfonates, such as alkyl, alkylaryl, or petroleum sulfonates, have been used above all as the oil-mobilizing tensides. However, these compounds exhibit a very low tolerance limit with respect to the salinity of the water present in the deposits. Salt concentrations as low as 1,000 ppm are considered problematic. The sensitivity of these tensides against alkaline earth metal ions is especially pronounced. In this connection, about 500 ppm is assumed to be the upper critical limit concentration (U.S. Pat. No. 4,110,228). When these tensides are utilized, precipitation products are formed in the presence of higher salt concentrations. These can plug up the formation. However, since many deposit waters possess substantially higher salinities, e.g. in Northern Germany up to 250,000 ppm, attempts have been made to find other ways to exploit the otherwise readily oil-mobilizing properties of the organic sulfonates also for deposit systems of higher salinity. Organic sulfonates do show a lesser electrolyte sensitivity in mixture with cosurfactants such as alcohols or nonionic tensides, but in such cases their oil-mobilizing effect is severely impaired as well.
In contrast to this group of compounds, alkyl or alkylaryl polyglycol ether sulfates or carboxymethylated alkyl or alkylaryl ethoxylates exhibit good compatibility even with extremely high salinities (e.g. 250,000 ppm) of the deposit waters. Since the oil-mobilizing effect of these tensides is high [H. J. Neumann, "DGMK BERICHTE" [Reports of the German Society for Petroleum Technology and Carbon Technology and Carbon Chemistry], Report 164 (1978); D. Balzer and K. Kosswig, Tenside Detergents 16:256 (1979)], and their manufacture is simple and economical, these classes of compounds are very highly suitable for use in oil displacement in medium- and high-salinity deposit systems (30,000-250,000 ppm total salt content).
In numerous investigations on residual oil mobilization using model formations with carboxymethylated ethoxylates as the tensides, however, it has been observed that the transport of the oil bank through the formation is accompanied by a strong pressure rise. Thus, even with a relatively highly permeable artificial formation, pressure gradients have been observed of up to about 40 bar/m. When applied to field operations, the results show pressures far above the petrostatic pressure, precluding the use of these tensides in tertiary oil recovery.
The literature also makes mention of pressure gradients of a similar magnitude [C. Marx, H. Murtada, M. Burkowsky, "Erdoel Erdgas Zeitschrift" [Petroleum Natural Gas News] 93:303 (1977)]. These authors explain the high pressure differences as a result of the formation of emulsion zones which are said, however, to be limited to the region of the flood front. Experiments, however, have not shown any local limitation of the pressure gradient. Inasmuch as crude oil emulsions stabilized by carboxymethylated ethoxylates are structurally viscous, the high pressure differences cannot be reduced at will by decreasing the flooding rate, either. Consequently, uncontrollably high pressure gradients must be expected in field experiments of tenside flooding with carboxymethylated ethoxylates.
Therefore, it is important to find a mode of operation for tenside flooding for the readily oil-mobilizing, carboxymethylated ethoxylates which does not lead to high pressure gradients. One way of lowering the pressure gradient is to attempt greatly delayed tenside breakthrough by a suitable adaptation of the quantity of tenside added to the deposit. However, this procedure presupposes homogeneous formations. These occur in artificial sand accumulations but hardly in actual reservoirs (deposits). Therefore, it is not possible to solve the problem in this way.